Various aspects of the Utility'sUtility’s business are subject to a complex set of energy, environmental and other laws, regulations, and regulatory proceedings at the federal, state, and local levels. In addition to enacting PUHCA 2005 to replace the Public Utility Holding Company Act of 1935, as discussed above, the EPAct significantly amended various federal energy laws applicable to electric and natural gas markets, including the Federal Power Act of 1935, the Natural Gas Act of 1938 and the Public Utility Regulatory Policies Act of 1978 (“PURPA”).

For discussion of specific pending regulatory proceedings and investigations that are expected to affect the Utility, see the sectionsections of MD&A entitled “Regulatory Matters” and “Natural Gas Matters” in the 20082011 Annual Report.

The FERC regulates the transmission of electricity and wholesale sales of electricity in interstate commerce and the transmission and sale of natural gas for resale in interstate commerce. The FERC also regulates interconnections of transmission systems with other electric systems and generation facilities;facilities, tariffs and conditions of service of regional transmission organizations, including the CAISO;California Independent System Operator Corporation (“CAISO”), and the terms and rates of wholesale electricity sales. The EPAct granted the FERC significant new responsibilities to oversee the reliability of the nation’s electricity transmission grid, to prevent market manipulation, and to supplement state transmission siting efforts in certain electric transmission corridors that are determined to be of national interest.  The EPAct also expanded the FERC’shas authority to impose penalties of up to $1,000,000 per day for violation of certain federal statutes, including the Federal Power Act of 1935 and the Natural Gas Act of 1938, and for violations of FERC-approved regulations. The FERC can impose penalties of up to $1,000,000 per day per violation.  The FERC has jurisdiction over the Utility'sUtility’s electricity transmission annual amount of revenue requirements(“revenue requirements”) and rates, the licensing of substantially all of the Utility'sUtility’s hydroelectric generation facilities, and the interstate sale and transportation of natural gas.

The FERC also has issued rules on electric transmission pricing reforms designed to promote needed investment in energy infrastructure, to reduce transmission congestion, and to require transmission organizations with organized electricity markets to make long-term firm transmission rights available to load-serving entities, so these entities can enter into long-term transmission service arrangements without being exposed to unhedged congestion cost risk. In addition, pursuant to FERC orders, the CAISO is responsible for providing open access electricity transmission service on a non-discriminatory basis, planning transmission system additions, and ensuring the maintenance of adequate reserves of generation capacity.

The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the two nuclear generating units at Diablo Canyon and the Utility’s retired nuclear generating unit at Humboldt Bay (“Humboldt Bay Unit 3”). NRC regulations require extensive monitoring and review of the safety, radiological, seismic, environmental, and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. NRC safety and security requirements have, in the past, necessitated substantial capital expenditures at Diablo Canyon, and additional significant capital expenditures could be required in the future.

The NRC operating license for Diablo Canyon Unit 1 expires in November 2024 and the NRC operating license for Diablo Canyon Unit 2 expires in August 2025. UnderIn November 2009, the termsUtility filed an application at the NRC to begin the license renewal process which is expected to take several years as the NRC holds public hearings and conducts safety and environmental analyses and site audits. At the Utility’s request, the NRC has agreed to delay processing the Utility’s application until the Utility completes extensive seismological studies in 2015 or 2016.

Following the March 2011 earthquake and tsunami that caused significant damage to nuclear facilities in Japan, the NRC appointed a task force to develop recommendations about how to improve safety at U.S. nuclear power plants and upgrade protection against earthquakes, floods and power losses. The twelve safety recommendations were released in July 2011 and have been reviewed by the NRC staff. During 2012, it is expected that the NRC will adopt regulations or issue orders requiring nuclear power plants to implement some of these licenses, there must be sufficient storage capacitythe near-term recommendations. The NRC is expected to implement the remaining recommendations over the next five years.

For more information about the relicensing proceeding and other matters affecting Diablo Canyon, see the section of MD&A in the 2011 Annual Report entitled “Regulatory Matters–Diablo Canyon Nuclear Power Plant.”

The Pipeline and Hazardous Materials Safety Administration

The Utility also is subject to regulations adopted by the federal Pipeline and Hazardous Materials Safety Administration (“PHMSA”) that is within the United States Department of Transportation. The PHMSA develops and enforces regulations for the radioactive spent fuel produced by the Diablo Canyon plant.  For a discussionsafe, reliable, and environmentally sound operation of the Utility’s spent fuel storage project, see “Environmental Matters – Nuclear Fuel Disposal,” below.

The Utility'sUtility’s operations have been significantly affected by various statutes passed by the California Legislature, including:

The CPUC consists of five members appointed by the Governor of California and confirmed by the California State Senate for staggered six-year terms. The CPUC has jurisdiction to setover the rates and terms and conditions of service for the Utility'sUtility’s electricity distribution, electricity generation,and natural gas distribution operations, electricity generation, and natural gas transportation and storage services in California.services. The CPUC also has jurisdiction over the Utility'sUtility’s issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility'sUtility’s electricity and natural gas retail customers, raterates of return, rates of depreciation, aspects of the siting and operation of natural gas transportation assets, oversight of nuclear decommissioning, and aspects of the siting of facilities used in providing electric and natural gas utility service.

The CPUC also enforces laws that set forth safety requirements pertaining to the electricitydesign, construction, testing, operation, and maintenance of utility gas gathering, transmission, system. and distribution pipeline systems, and for the safe operation of such pipelines and equipment. The CPUC also has been delegated authority to enforce compliance with certain federal regulations related to the safety of natural gas facilities.

Ratemaking for retail sales from the Utility'sUtility’s generation facilities is under the jurisdiction of the CPUC. To the extent that this electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. In addition, the CPUC has general jurisdiction over most of the Utility’s operations, and regularly reviews the Utility’s performance, using measures such as the frequency and duration of outages. The CPUC also conducts investigations into various matters, such as deregulation, competition, and the environment, in order to determine its future policies. The CPUC consists of five members appointed by the Governor of California and confirmed by the California State Senate for staggered six-year terms.

PG&E Corporation and the Utility entered into a settlement agreement with the CPUC on December 19, 2003, to resolve the Utility'sUtility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code that had been pending in the U.S. Bankruptcy Court for the Northern District of California (“Bankruptcy Court”) since April 2001 referred to as the (“Chapter 11 Settlement Agreement.Agreement”). The nine-year Chapter 11 Settlement Agreement established certain regulatory assets and addressed various ratemaking matters to restore the Utility’s financial health and enable it to emerge from Chapter 11. The terms of the Chapter 11 Settlement Agreement were incorporated into the Utility’s plan of reorganization under Chapter 11, which became effective on April 12, 2004. The Bankruptcy Court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation, or enforcement of the Chapter 11 Settlement Agreement, in addition to other matters. (For more information, see Note 15 of the Notes to the Consolidated Financial Statements included in the 2008 Annual Report.)

The California Energy Resources Conservation and Development Commission, commonly called the California Energy Commission (“CEC”), is the state'sstate’s primary energy policy and planning agency. The CEC is responsible for licensing of all thermal power plants over 50 MW, overseeing funding programs that support public interest energy research, advancing energy science and technology through research, development and demonstration, and providing market support to existing, new, and emerging renewable technologies. In addition, the CEC is responsible for forecastingforecasts of future energy needs used by the CPUC in determining the adequacy of the utilities'utilities’ electricity procurement plans.

The Utility obtains permits, authorizations, and licenses in connection with the construction and operation of the Utility'sUtility’s generation facilities, electricity transmission lines, natural gas transportation pipelines, and gas compressor station facilities. DischargeThese permits include discharge permits, various Air Pollution Control District permits, U.S. Department of Agriculture-Forest Service permits, FERC hydroelectric generation facility and transmission line licenses, and NRC licenses are some of the more significant examples.licenses. Some licenses and

The Utility has over 520 franchise agreements with various292 cities and counties that permit the Utility to install, operate, and maintain the Utility'sUtility’s electric and natural gas facilities in the public streets and roads. In exchange for the right to use public streets and roads, the Utility pays annual fees to the cities and counties. Franchise fees are computed pursuant to statute under either the Broughton Act or the Franchise Act of 1937. In addition, charter cities can negotiate their fees. In most cases, the Utility’s franchise agreements are for an indeterminate term, with no expiration date. The Utility has several franchise agreements that have a specified term of years, including an agreement with a large charter city. The franchise agreements generally require that the Utility install and maintain the electric and gas facilities in compliance with regulations adopted by cities and counties in the exercise of their police powers relating to the use of the public streets. The Utility also periodically obtains permits, authorizations, and licenses in connection with distribution of electricity and natural gas. Under these permits, authorizations, and licenses, the Utility has rights to occupy and/or use public property for the operation of the Utility'sUtility’s business and to conduct certain related operations.

Even before the passage of the EPAct, the FERC'sFERC’s policies supported the development of a competitive electricity generation industry. FERC Order 888, issued in 1996, established standard terms and conditions for parties seeking access to regulated utilities'utilities’ transmission grids. Order 888 requires all public utilities that own, control, or operate, facilities used for transmitting electric energy in interstate commerce to have on file an open access non-discriminatory transmission tariff (“OATT”) that contains minimum terms and conditions of non-discriminatory service. The FERC'sFERC’s subsequent Order 2000, issued in late 1999, established national standards for regional transmission organizations, and advanced the view that a regulated unbundled transmission sector should facilitate competition in both wholesale electricity generation and retail electricity markets. On February 16, 2007, the FERC issued Order 890, which is designed to: (1) strengthen the form of the OATT adopted in Order 888 to ensure that tariffs achieve their original purpose of remedying undue discrimination;discrimination, (2) provide greater specificity in the form of the OATT to reduce opportunities for undue discrimination and facilitate the FERC’s enforcement;enforcement, and (3) increase transparency in the rules applicable to planning and use of the transmission system.

The FERC also has issued rules on the interconnection of generators to require regulated transmission providers, such as the Utility or the CAISO, to use standard interconnection procedures and a standard agreement for generator interconnections. These rules are intended to limit opportunities for transmission providers to favor their own generation, facilitate market entry for generation

In addition, the Utility’s customers may, under certain circumstances, obtain power from a “communitycommunity choice aggregator”aggregator (“CCA”) instead of from the Utility. California Assembly Bill 117, enacted in 2002,law permits cities and counties and certain other public agencies to purchase and sell electricity for their local residents and businesses onceafter they have registered as community choice aggregators.CCAs. Under Assembly Bill 117,these arrangements, the Utility would continuecontinues to provide distribution, metering, and billing services to the community choice aggregators' customers of the CCAs and would be those customers'remains the electricity provider of electricity of last resort.  However, once registration has occurred, each community choice aggregator wouldresort for those customers. The law provides that a CCA can procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility. The CPUC has adopted rules to implement community choice aggregation,the CCA program, including the imposition of a surcharge on retail end-users of the community choice aggregatorCCA to prevent a shifting of costs to customers of a utility who receive bundled services. Assembly Bill 117services and allowing a CCA to start service in phases. The law also authorizedauthorizes the Utility to recover from each community choice aggregatorCCA any costs of implementing the program that are reasonably attributable to the community choice aggregator,CCA, and to recover from all customers any costs of implementing the program not reasonably attributable to a community choice aggregator.  NoCCA.

In some circumstances, governmental entities such as cities and irrigation districts, which have authority under the state constitution or counties are currently operating as community choice aggregators, butstate statute to provide retail electric service, seek to acquire the Utility’s distribution facilities. For example South San Joaquin Valley Power AuthorityIrrigation District (“SSJID”) has filed an implementation planapplied to San Joaquin County Local Agency Formation Commission for the authority to provide electric distribution service in and statedaround the cities of Manteca, Ripon and Escalon. SSJID has indicated that, if it may begin operatingreceives the requested authority, it will seek to acquire the Utility’s distribution facilities, either under a consensual transaction, or via eminent domain.

It is also possible that technological developments could pose competitive challenges for traditional utilities. In particular, a combination of technology-related cost declines and sustained federal or state subsidies could make “distributed generation” a viable, cost-effective alternative to the Utility’s bundled electric service. The CPUC also has been considering the role of electric vehicles in 2009.California’s electricity infrastructure. In addition,July 2010, the CountyCPUC found that although the California Legislature did not intend that the CPUC regulate providers of Marinelectric vehicle charging services as public utilities, the CPUC has authority to regulate aspects of electric vehicle charging services. These aspects include rules relating to the deployment of electric vehicles; the terms under which a utility will provide services to electric vehicle charging providers; retail electricity rates paid by electric vehicle charging providers to a regulated utility; standards and several citiesprotocols to ensure functionality and interoperability between utilities and electric vehicle charging providers; and various electricity procurement requirements that apply to electricity service providers generally, such as resource adequacy and renewable energy procurement standards. A second phase of the CPUC proceeding will examine the role of the regulated utility in that county have votedelectric vehicle charging programs, ways to pursue community choice aggregationmanage the impact of such programs on the electric infrastructure, the cost to customers of such programs, and have formed a joint powers agency to do so, but have not yet filed an implementation plan.

FERC Order 636, issued in 1992, required interstate natural gas pipeline companies to divide their services into separate gas commodity sales, transportation, and storage services. Under Order 636, interstate natural gas pipeline companies must provide transportation service whether or not the customer (often a local gas distribution company) buys the natural gas commodity from these companies. The Utility’s natural gas pipelines are located within the State of California and are exempt from most of the FERC’s rules and regulations applicable to interstate pipelines; the Utility’s pipeline operations are instead subject to the jurisdiction of the CPUC.

The Utility’s gas transmission and storage system has operated under the CPUC-approved “Gas Accord” market structure since 1998. This market structure largely mimics the regulatory framework required by the FERC for interstate gas pipelines. The CPUC divides

The Gas Accord separated the Utility’s natural gas transmission and storage rates from its distribution services and rates. The Gas Accord also changed the nature of the Utility’s transmission and storage services by creating path-specific transmission services, firm and interruptible service offerings, standard and negotiated rate options, and a secondary market for trading of firm capacity rights. Additionally,In addition, the Gas Accord eliminated balancing account protection for some services, increasing the Utility’s risk/reward potential.

The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services. The most important competitive factor affecting the Utility'sUtility’s market share for transportation of natural gas to the southern California market is the total delivered cost of western Canadian and U.S. Rocky Mountains natural gas delivered to northern California, relative to the total delivered cost of natural gas from the southwestern United States. The total delivered cost of natural gas includes, in addition to the commodity cost, transportation costs on all pipelines that are used to deliver the natural gas, which, in the Utility'sUtility’s case, includes the cost of transportation of the natural gas from Canada and the U.S. Rocky Mountains to the California border and the amount that the Utility charges for transportation from the border to southern California. In general, when the total cost of western Canadian and U.S. Rocky Mountains natural gas delivered to northern California increases relative to other competing natural gas sources, the Utility'sUtility’s market share of transportation services into southern California decreases. The Utility also competes for storage services with other third-party storage providers, primarily in northern California.

The Utility’s rates for electricity and natural gas utility services are based on its costs of providing service (“cost-of-service ratemaking”). Before setting rates, the CPUC and the FERC conduct proceedings to determine the annual amount of revenue (“revenue requirements”)requirements that the Utility is authorized to collect from its customers. The CPUC determines the Utility’s revenue requirements associated with electricity and gas distribution operations, electricity generation, and natural gas transportation and storage. The FERC determines the Utility’s revenue requirements associated with its electricity transmission operations.

Revenue requirements are designed to allow a utility an opportunity to recover its reasonable operating and capital costs of

Regulatory balancing accounts are used to adjust the Utility’s revenue requirements. Sales balancing accounts track differences between the Utility’s recorded revenues and its authorized revenue requirements, due primarily to sales fluctuations. In general, electricity sales are higher in the summer months and natural gas sales are higher in the winter months. Cost balancing accounts track differences between the Utility’s incurred costs and its authorized revenue requirements, most importantly for energy commodity costs and volumes that can be affected by seasonal demand, weather, and other factors. Balances in all CPUC-authorized accounts are subject to review, verification audit, and adjustment, if necessary, by the CPUC.

To develop retail rates, the revenue requirements are allocated among customer classes (mainly residential, commercial, industrial, and agricultural) and to various service components (mainly customer, demand, and energy). Specific rate components are designed to produce the required revenue. Rate changes become effective prospectively on or after the date of CPUC or FERC decisions. Most rate changes approved by the CPUC throughout the year are consolidated to take effect on the first day of the following year.

Through cost-of-service ratemaking, rates are developed to produce the revenue requirements, including the authorized return on rate base. The Utility may be unable to earn its authorized rate of return because the CPUC or the FERC excludes some of the Utility’s actual costs from the revenue requirements or because the Utility’s actual costs are higher than those reflected in the revenue requirements.

While the CPUC generally uses cost-of-service ratemaking to develop revenue requirements and rates, it selectively uses incentive ratemaking, which bases rates on the extent to which the utilities meet objective or fixed standards or goals, such as reliability standards or energy efficiency goals, instead of on the cost of providing service.

The General Rate Case (“GRC”) is the primary proceeding in which the CPUC determines the amount of revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s basic business and operational costs related to its electricity and natural gas distribution and electricity generation operations. The CPUC generally conducts a GRC every three years. The CPUC sets revenue requirement levels for a three-year rate period based on a forecast of costs for the first or “test” year. Typical interveners in the Utility'sUtility’s GRC include the CPUC’s Division of Ratepayer Advocates and The Utility Reform Network.

On March 15, 2007,May 5, 2011, the CPUC approvedissued a multi-party settlement agreementfinal decision in the 2011 GRC to resolveauthorize the Utility’s 2007 GRC.  The decision set the Utility’s electricityrevenue requirements for 2011 through 2013 for its costs to own and operate its electric and natural gas distribution and electricityelectric generation operations. The final decision approves the unopposed October 15, 2010 settlement agreement among the Utility, the DRA, TURN, and nearly all other intervening parties. The CPUC authorized a total 2011 revenue requirementsrequirement of approximately $6.0 billion, which reflects an overall increase of $450 million, or 8.0%, over

the total 2010 authorized amount of $5.6 billion, including $55 million for the recovery of financing costs and the accelerated return of capital associated with conventional meters that have been replaced by SmartMeter^TM devices. As soon as July 2012, the Utility may file a four-year period, from 2007 through 2010, rather than for a typical three-year period.  Undernotice of intent with the decision, the Utility’s next GRCCPUC that will be effective January 1, 2011. The Utility intends to submitinclude a draft of the 2011Utility’s GRC application and revenue requirement requestfor the period beginning January 1, 2014. The Utility plans to the CPUCfile its GRC application in July or August 2009.  For more information, see the section of MD&A entitled “Results of Operations” in the 2008 Annual Report.

The CPUC may authorize the Utility to receive annual increases for the years between GRCs in the base revenues authorized for the test year of a GRC in order to avoid a reduction in earnings in those years due to, among other things, inflation and increases in invested capital. These adjustments are known as attrition rate adjustments. Attrition rate adjustments provide increases in the revenue requirements that the Utility is authorized to collect in rates for electricity and natural gas distribution and electricity generation operations. The CPUC’sCPUC decision in the Utility’s 20072011 GRC includes a provisionalso authorized attrition increases of $180 million for attrition adjustments made in 2008,2012 and to be made in 2009 and 2010.  For more information, see the section of MD&A entitled “Results of Operations” in the 2008 Annual Report.

The CPUC generally conducts a proceeding to determineauthorizes the Utility's authorizedUtility’s capital structure (i.e., the relative weightings of common equity, preferred equity, and debt) and the authorized raterates of return on each component that the Utility may earn on its electricity and natural gas distribution and electricity generation assets. The current authorized capital structure, consisting of 52% equity, 46% long-term debt, and 2% preferred stock, will remain in effect through 2012.

The CPUC has adopted a cost of capital proceeding establishes the relative weightings of common equity, preferred equity and debt in the Utility's total authorized capital structure. The CPUC then establishes the authorized return on each component that the Utility will collect in its authorized rates.  In May 2008, the CPUC adopted a uniform three-year cost of capitaladjustment mechanism to set the cost of capital for the Utility and the other two California investor-owned electric utilities.  The utilities are required to file full cost of capital applications by April 20 of every third year, beginning on April 20, 2010.

This mechanism did not trigger a change in the Utility’s authorized cost of debt, preferred stock, or equity for 2009.

The utilities may apply for an adjustment to either theUtility’s next full cost of capital or the capital structure sooner basedapplication must be filed by April 20, 2012, so that any resulting changes would become effective on extraordinary circumstances.

Although the FERC has authority to set the Utility’s rate of return for its electricity transmission operations, the rate of return is often unspecified if the Utility'sUtility’s transmission rates are determined through a negotiated rate settlement.

In December 2011, the CPUC approved the Utility’s bundled electricity procurement plan, covering 2011 through 2020, subject to certain required modifications. The Utility intends to file a revised bundled electricity procurement plan in April 2012 that is consistent with the CPUC’s December 2011 decision.

Although California legislation requiring the CPUC to adjust a utility’s retail electricity rates when the forecast aggregate over-collections or under-collections in the ERRA exceed 5% of a utility'sutility’s prior year electricity procurement revenues (excluding amounts collected for the DWR contracts) expired on January 1, 2006, the CPUC has extended this mandatory rate adjustment mechanism for the length of a utility’s resource commitment or 10 years, whichever is longer. The CPUC also performs compliance reviews of the procurement activities recorded in the ERRA to ensure that the Utility’s procurement activities are in compliance with its approved procurement plans. The Chapter 11 Settlement Agreement also provides that the Utility will recover its reasonable costs of providing utility service, including power purchase costs.

The CPUC has approved severalvarious power purchase agreements that the Utility has entered into with third parties in accordance with the Utility’s CPUC-approved long-term procurement plan and to meet renewable energy and resource adequacy requirements. The CPUC also authorized the Utility to recover fixed and variable costs associated with these contracts through the ERRA.

The non-bypassable charge can be imposed from the date of signing a power purchase agreement and can last for 10 years from the date the new generation unit comes on line or for the term of the contract, whichever is less. Utilities are allowed to justify a cost recovery period longer than 10 years on a case-by-case basis. If a utility elects to useuses the net capacity cost allocation method, the net capacity costs would beare allocated for the term of the contract or 10 years, whichever is less, starting on the date the new generation unit comes on line.  Under this allocation mechanism, the energy rights to the contract are auctioned off to maximize the energy revenues and minimizecontract. To use the net capacity costsallocation, the CPUC must determine that would be subjecta resource was needed to allocation.  If no bids are acceptedmeet system or local area reliability needs for the benefit of all distribution customers. The CPUC can decide whether to require an energy rights, the Utility would retain the rightsauction for resources subject to the energy and would value it at market prices for the purposes of determining the net capacity cost allocation.

For renewable generation purchased from third parties under power purchase agreements, the Utility may recover any above-market costs to be allocated untilthrough the next periodic auction.

The CPUC-authorized revenue requirements for capital costs and non-fuel operating and maintenance costs for operating Utility-owned generation facilities are addressed in the Utility’s GRC. The CPUC-authorized revenue requirements to recover the initial capital costs for utility-owned generation projects are recovered through a balancing account, the Utility Generation Balancing Account (“UGBA”), which tracks the difference between the CPUC-approved forecast of initial capital costs, adjusted from time to time as permitted by the CPUC, and actual costs. The initial revenue requirement for the Utility-owned projects generally would begin to accrue in the UGBA as of the new facility’s commercial operation date or the date a completed facility is transferred to the Utility, and would be included in rates on January 1 of the following year. For more information, see the section of MD&A entitled “Capital Expenditures – New Generation Facilities”Expenditures” in the 20082011 Annual Report.

During the 2000-2001 California 2000-2001 energy crisis, the DWR entered into long-term contracts to purchase electricity from third parties. The electricity provided under these contracts has been allocated to the electric customers of the three California investor-owned electric utilities. The DWR pays for its costs of purchasing electricity from a revenue requirement collected from these

The Utility'sUtility’s electricity transmission revenue requirements and its wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two main sources of transmission revenues: (1) charges under the Utility'sUtility’s transmission owner tariff and (2) charges under specific contracts with wholesale transmission customers that the Utility entered into before the CAISO began its operations in March 1998. These wholesale customers are referred to as existing transmission contract customers and are charged individualized rates based on the terms of their contracts. Other customers pay transmission rates that are established by the FERC in the Utility'sUtility’s transmission owner tariff rate cases. These FERC-approved rates are included by the CPUC in the Utility'sUtility’s retail electric rates, consistent with the federal filed rate doctrine, and are collected from retail electric customers receiving bundled service.

The primary FERC rate-makingratemaking proceeding to determine the amount of revenue requirements that the Utility is authorized to recover for its electric transmission costs and to earn its return on equity is the transmission owner rate case (“TO rate case”). The Utility generally files a TO rate case every year, setting rates for a one-year period.year. The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process.  For more information about the

The Utility’s TO rate cases, see the section of MD&A entitled “Regulatory Matters — Electric Transmission Owner Rate Cases” in the 2008 Annual Report.

The other component consists of rates intended to reflect credits and charges from the CAISO. The CAISO credits the Utility for transmission revenues received by the CAISO.  These revenues include:

The CAISO also charges the Utility for reliability service costs and imposes a transmission access charge on the Utility for the Utility’s use of the CAISO-controlled electric transmission grid in serving its customers. The CAISO's transmission access charge methodology, approved by the FERC in December 2004, provides for a transition over a 10-year period, from 2000-2009, to a uniform statewide high-voltage transmission rate. This rate is based on the revenue requirements associated with facilities operated at 200 kV and above of all transmission-owning entities that become participating transmission owners under the CAISO tariff. The transmission access charge methodology may resultresults in a cost shift fromto transmission owners, whose costs for existing transmission facilities at 200 kV and above are higher than thatthose embedded in the uniform transmission access charge rate, tofrom transmission owners with lower embedded costs for existing high voltage transmission, such as the Utility. The Utility's obligationcost shift amounts are recovered from the Utility’s retail customers as part of retail transmission rates.

Natural Gas

Natural Gas Transmission and Storage Rate Cases

The CPUC determines the Utility’s authorized revenue requirements and rates for this cost differential has been capped at $32 million per year duringits natural gas transmission and storage services in a separate rate case called the 10-year transition period.

Certain of the Utility'sUtility’s natural gas distribution costs and balancing account balances are allocated to customers in the CPUC’s Biennial Cost Allocation Proceeding. This proceeding normally occurs every two years and is updated in the interim year for purposes of adjusting natural gas rates to recover from customers any under-collection, or refund to customers any over-collection, in the balancing accounts. Balancing accounts for gas distribution and other authorized expenses accumulate differences between authorized amounts and actual revenues.

The Utility sets the natural gas procurement rate for core customers monthly, based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rates.

The Utility recovers the cost of gas (subject to the ratemaking mechanism discussed below), acquired on behalf of core customers, through its retail gas rates. (The Utility recovers the cost of gas used in generation facilities as a cost of electricity that is recovered through electricity balancing accounts.)

The Utility is protected against after-the-fact reasonableness reviews of these gas procurement costs under an incentive mechanism, the CPIM.Core Procurement Incentive Mechanism (“CPIM”). Under the CPIM, the Utility'sUtility’s purchase costs for a fixed twelve-month12-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the commodity benchmark, are considered reasonable and are fully recovered in customers'customers’ rates. One-half of the costs above 102% of the benchmark are recoverable in customers'customers’ rates, and the Utility'sUtility’s customers receive in their rates 80% of any savings resulting from the Utility'sUtility’s cost of natural gas that is less than 99% of the benchmark. The shareholder award is capped atremaining amount of savings are retained by the lower ofUtility as incentive revenues, subject to a cap equal to 1.5% of total natural gas commodity costs or $25 million.costs. While this incentive mechanism remains in place, changes in the price of natural gas, consistent with the market-based benchmark, are not expected to materially impact net income.

In January 2010, the CPUC approved a joint settlement agreement among the Utility, the CPUC’s Division of Ratepayer Advocates, and The Utility also has received CPUC approvalReform Network to incorporate a portion of hedging costs for a long-term gas hedging program on behalf of core customers into the Utility’s CPIM beginning November 1, 2010. The settlement agreement has an initial term of seven years, through 2011.  The costsOctober 2017, which can be extended by agreement of the parties. As a result, the settlement agreement permits the Utility to develop and implement a sustained core hedging program are recovered directly from gas customers, outside the CPIM mechanism, and are subject only to a compliance review, not an after-the

The Utility'sUtility’s interstate and Canadian natural gas transportation agreements with third-party service providers are governed by tariffs that detail rates, rules, and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines. United States tariffs are approved for each pipeline for service to all of its shippers, including the Utility, by the FERC in a FERC ratemaking review process, and the applicable Canadian tariffs are approved by the Alberta Utilities Commission and the National Energy Board. The Utility'sUtility’s agreements with interstate and Canadian natural gas transportation service providers are administered as part of the Utility'sUtility’s core natural gas procurement business. Their purpose is to transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada, the U.S. Rocky

Mountains, and the southwestern United States) to the points at which the Utility'sUtility’s natural gas transportation system begins. For more information, see the discussion below under “Natural Gas Utility Operations –— Interstate and Canadian Natural Gas Transportation Services Agreements.”

The following table showsUtility is required to maintain physical generating capacity adequate to meet its customers’ load, including peak demand and planning and operating reserves, deliverable to the percentage of the Utility's total sources of electricity for 2008 represented by each major electricity resource:

At December 31, 2008,2011, the Utility owned and operated the following generation facilities, all located in California, listed by energy source:

The ability of the Utility to produce nuclear generation depends on the availability of nuclear fuel. The Utility has entered into various purchase agreements for nuclear fuel that are intended to ensure long-term fuel supply. For more information about these agreements, see Note 17:15: Commitments and Contingencies—Contingencies — Nuclear Fuel Agreements, of the Notes to the Consolidated Financial Statements in the 20082011 Annual Report.

The following table outlines the Diablo Canyon power plant'splant’s refueling schedule for the next five years. The Diablo Canyon power plant refueling outages are typically scheduled every 20 months. The average length of a refueling outage over the last five years has been approximately 51 days.  The Utility will replace the steam generators in Unit 1 during the scheduled refueling outage that began in January 2009.  Due to this additional work, this refueling outage is expected to last approximately 7644.6 days. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.

During 2008,2011, electricity from the DWR contracts allocated to the Utility provided approximately 15%3.57% of the electricity delivered to the Utility'sUtility’s customers. The DWR purchased the electricity under contracts with various generators. The Utility, as an agent, is responsible for administration and dispatch of these DWR contracts and acts as a billing and collection agent. The DWR remains legally and financially responsible for its contracts. The Utility expects that the amount of power supplied under the DWR’s contracts will diminish in the future as thethese contracts expire or terminate.  For more information regarding the DWR contracts, see Note 17: Commitments and Contingencies – California Department of Water Resources Contracts, of the Notesare novated to the Consolidated Financial Statements in the 2008 Annual Report.

For more information regarding the Utility'sUtility’s power purchase contracts, see Note 17:15: Commitments and Contingencies—Contingencies — Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 20082011 Annual Report.

Renewable generation resources include biomass, small hydroelectric, wind, solar, and geothermal energy. In April 2011, the California Governor signed legislation that establishes a new RPS that requires load-serving entities, such as the Utility, to increase the amount of renewable energy they procure from at least 20% of their total retail sales, as required by the prior RPS law, to 33% of their total retail sales. The Utility’s CPUC-approved long-term electricityRPS law establishes three initial compliance periods: 2011-2013, 2014-2016, and 2017-2020. The RPS compliance requirement that must be met for each of these compliance periods will gradually increase. Thereafter, compliance with the 33% RPS requirement will be determined on an annual basis.

The new RPS law creates three distinct categories (or “buckets”) of renewable energy products that can be used to meet the RPS requirements and imposes minimum or maximum procurement plan, coveringtargets for each of these product categories for each compliance period. With certain exceptions, these categorical requirements will only apply to renewable energy contracts entered into after June 1, 2010. The new law also (1) limits the use of certain types of unbundled renewable energy credits and (2) restricts the ability to carry forward (or “bank”) RPS volumes from certain types of short-term contracts, to satisfy compliance obligations.

On December 15, 2011, the CPUC issued a decision to adopt the criteria for each “portfolio content category.” The decision requires all retail sellers to provide sufficient information about their RPS procurement during 2007-2016, forecastsso the CPUC can make a compliance determination that the Utilityretail seller’s RPS procurement actually meets the requirements of the portfolio content category which the retail seller claims. In addition, investor-owned utilities must provide specific information when seeking CPUC approval of RPS procurement contracts that will needallow the CPUC to obtainevaluate the proposed portfolio content category of the planned procurement, and the value and risk of the planned procurement to the utilities’ ratepayers.

In addition, the CPUC is expected to determine whether to change the penalty provisions established under the former RPS law, which provided for a maximum penalty of $25 million per year on each load-serving entity that had an additional 800unexcused failure to 1,200 MW ofmeet its compliance obligation. Until the CPUC adopts regulations to implement the new conventional generation by 2015 abovelaw, it is uncertain how the Utility's planned additionsCPUC’s regulations and decisions issued pursuant to the former RPS statute, including the penalty provisions, will apply to the new RPS requirements.

Additionally, the CEC, which continues to have responsibility for certifying the eligibility of renewable resources and verifying LSE compliance with the RPS program, has also initiated a proceeding to implement the new RPS law and is expected to issue one or more draft regulations in the second quarter of 2012.

The costs incurred by the Utility under third-party contracts to meet RPS requirements are tracked in a balancing account and recovered through rates. The costs of Utility-owned renewable generation projects will be recoverable through traditional cost-of-service ratemaking mechanisms provided that costs do not exceed the maximums authorized by the CPUC for the respective project.

For the year ended December 31, 2011, the Utility’s RPS-eligible renewable resource deliveries equaled 19.3% of its total retail electricity sales. Most renewable energy efficiency, demand reduction programs,deliveries resulted from third party contracts, mainly QF agreements and previously approvedbilateral contracts. Additional renewable resources included the Utility’s small hydroelectric and solar facilities and certain irrigation district contracts for new generation resources.

For more information regarding the Utility's proposal,Utility’s renewable energy contracts, see Note 15: Commitments and Contingencies — Third-Party Power Purchase Agreements, of the section of MD&A entitled “Capital Expenditures ─ Proposed New Generation Facilities”Notes to the Consolidated Financial Statements in the 20082011 Annual Report.

At December 31, 2008,2011, the Utility owned 18,650approximately 18,618 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 56,401approximately 59,743 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 141,036approximately 141,000 circuit miles of distribution lines and substations with a capacity of 27,13729,066 MVA. In 2008,2011, the Utility delivered 88,12774,684 GWh to its customers; including 6,191customers, and approximately 8,494 GWh delivered to direct access customers. The Utility is interconnected with electric power systems in the WECC, which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico.

During 1998, in connection with electric industry restructuring, the California investor-owned electric utilities relinquished control, but not ownership, of their transmission facilities to the CAISO. The Utility entered into a Transmission Control Agreement with the CAISO and other participating transmission owners (including Southern California Edison Company, San Diego Gas & Electric Company, and several California municipal utilities) under which the transmission owners have assigned operational control of their electric transmission systems to the CAISO. The Utility is required to give the CAISO two years notice and receive approval from the FERC if it wishes to withdraw from the Transmission Control Agreement and take back operational control of its transmission facilities.

The CAISO, which is regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. The CAISO also is responsible for ensuring that the reliability of the transmission system is maintained. The Utility acts as a scheduling coordinator to schedule electricity deliveries to the transmission grid. The Utility also acts as a scheduling coordinator to deliver electricity produced by several governmental entities to the transmission grid under contracts the Utility entered into with these entities before the CAISO commenced operation in 1998. In addition, under the mandatory reliability standards implemented following the EPAct, all users, owners, and operators of the transmission system, including the Utility, are also responsible for maintaining reliability through compliance with the reliability standards. See the discussion of reliability standards above under “The Utility’s Regulatory Environment-FederalEnvironment — Federal Energy Regulation.”

The Utility'sUtility’s electricity distribution network extends through 47 of California'sCalifornia’s 58 counties, comprising most of northern and central California. The Utility'sUtility’s network consists of 141,036approximately 141,000 circuit miles of distribution lines (of which approximately 19%20% are underground and approximately 81%80% are overhead). There are 9291 transmission substations and 4857 transmission-switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. The Utility’s network includes 607 distribution substations and 110 low-voltage601 distribution substations. The 4957 combined transmission and distribution substations have both transmission and distribution transformers.

The Utility'sUtility’s distribution network interconnects to the Utility'sUtility’s electricity transmission system at 1,106approximately 1,758 points. This interconnection between the Utility'sUtility’s distribution network and the transmission system typically occurs at distribution substations where transformers and switching equipment reduce the high-voltage transmission levels at which the electricity transmission system transmits electricity, ranging from 500 kV to 60 kV, to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility'sUtility’s customers. The distribution substations serve as the central hubs of the Utility'sUtility’s electricity distribution network and consist of transformers, voltage regulation equipment, protective devices, and structural equipment. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution lines or other facilities to entities, such as municipal and other utilities, that then resell the electricity.

Much of the Utility’s electric transmission and distribution infrastructure was placed into service in the 1940’s through the 1960’s as California’s population and economy grew. The Utility beganmakes capital investments in its electric transmission and distribution infrastructure to extend the installationlife of or replace existing infrastructure; to maintain and improve system reliability, safety, and customer service; and to add new infrastructure to meet customer demand growth.

The Utility has been installing an advanced metering infrastructure known asusing SmartMeter^TM technology throughout its service territory. As of December 31, 2011, the SmartMeter™ program, for virtually all of the Utility'sUtility has installed approximately 8.9 million advanced electric and gas customers.  These meters enable the Utility to measurethrough its service territory. Advanced electric meters, which record energy usage on anin hourly basis for electricity and on a daily basis for natural gas, which canor quarter-hourly increments, allow for demand-response rates to encourage customers to reducetrack energy consumption during peak demand periods,usage throughout the billing month and thus reducing peak period procurementenable greater customer control over electricity costs. Advanced meters can record usage in time intervalsUsage data is collected through a wireless communication network and be read remotely.  Thetransmitted to the Utility’s information system where the data is stored and used for billing and other Utility expectsbusiness purposes.

Following customer complaints that the new metering system led to completeovercharges, the CPUC began an investigation and several municipalities took various steps to delay or suspend the installation of the network infrastructure and advanced meters throughout its service territory by the end of 2011.  The Utility also has requestednew meters. On February 1, 2012, the CPUC issued a decision that permits customers to approve the Utility’s proposal to upgrade elementsopt out of the Utility’s SmartMeter™ SmartMeter^TMprogram. The Utility seeks approval to install solid-state electric meters and associated devices that would offer an expanded range of service features for customers and increased operational efficiencies for the Utility.  These upgraded meters and associated devices would provide additional energy conservation and demand response options for electric customers.  In addition, the solid-state electric meters are designed to facilitate the Utility’s ability to incorporate future advanced metering technology innovations in a timely and cost-effective manner.  (For moreFor information about the advanced metering infrastructure,these matters, see the section of MD&A entitled “Capital Expenditures ─ SmartMeter™ Program”“Regulatory Matters – Deployment of SmartMeter^TM Technology” in the 20082011 Annual Report.)

The following table shows certain of the Utility'sUtility’s operating statistics from 20042007 to 20082011 for electricity sold or delivered, including the classification of sales and revenues by type of service.